Performing measurements on fluid samples is desirable in many oil industry applications. In the prior art, such measurements are typically made by bringing samples to the surface using sealed containers, and sending the samples for laboratory measurements. A number of technical and practical limitations are associated with this approach.
The main concern usually is that the sample(s) taken to the surface may not be representative of the downhole geologic formation due to the fact that only a limited number of samples can be extracted and taken to the surface. In addition, because these samples frequently contain highly flammable hydrocarbon mixtures under pressure, handling of such test samples can be both hazardous and costly.
Nuclear magnetic resonance (NMR) technology has alleviated some of these problems by enabling a user to determine many properties of an in-situ formation fluid without extracting numerous samples. These properties include hydrogen density, self-diffusivity, and relaxation times, T.sub.1 and T.sub.2. The use of NMR measurements to determine formation properties is known in the field. For example, in U.S. patent application Ser. No. 08/996,716, filed Dec. 23, 1997, by the inventor of the present invention, a method and apparatus for making direct downhole NMR measurements of formation fluids is disclosed. The apparatus of the referenced disclosure is a downhole formation tester capable of providing NMR measurements such as hydrogen density, self-diffusivity, and relaxation times.
One problem not solved by the prior art is borne from the use of oil-based drilling muds (OBMs). The OBM filtrate that invades a drilled formation consists almost entirely of the continuous phase of the OBM. This synthetic or highly refined base oil cannot be reliably differentiated from the connate oil stored in the formation by conventional measurements--resistance, dielectric constant, and viscosity. In certain cases it is impossible to determine at what point the fluid pumped out by a downhole formation tester changes from OBM filtrate to crude oil. Collecting a sample of OBM filtrate is at best useless and at worst misleading about the hydrocarbon contents of a formation. It is therefore apparent that there is a need for a reliable and efficient method for differentiating between OBM filtrate and connate oil, a method that will enable the user to minimize costly surface extractions by employing the existing downhole NMR measurement technology.
The present method is based, in part, on the use of the equipment, described briefly above, disclosed by T. Blades and M. Prammer in U.S. patent application Ser. No. 08/996,716, filed Dec. 23, 1997. The disclosed device is a nuclear magnetic resonance (NMR) module fitted onto a modular formation tester. It uses small samples of the pumped fluid to determine parameters such as the hydrogen index, spin-lattice relaxation time T.sub.1, spin-spin relaxation time T.sub.2, and/or self-diffusivity, the measurement of which is based on hydrogen NMR relaxometry. The content of this application is hereby incorporated by reference for all purposes.
One of the few differentiating features between OBM filtrate and crude oil is that OBMs are composed of base oils that are non-toxic, highly refined or synthesized hydrocarbons. Molecular weight and molecular structure are in general well controlled. Crude oil, on the other hand, is a random mix of variable-length and variable-structure hydrocarbons. From an NMR standpoint, many refined or synthesized base oils are characterized by simple, well defined monoexponential relaxation spectra (either T.sub.1 or T.sub.2). By contrast, the crude oil mix exhibits a spectrum of internal characteristic relaxation times and diffusivities. They manifest themselves as a spectrum of relaxation times. While this difference in relaxation time behavior between OBM filtrate and crude oil has been known in the field, see R. Kleinberg and H. Vinegar, "NMR Properties of Reservoir Fluids," The Log Analyst, vol. 37, no. 6 (November-December 1996), pp.20-32, it has not been applied in the context of downhole testing to separate the fluid phases and to tell at what point a sample of connate oil has been obtained in a downhole fluid sampler. It should be pointed out that the relaxation time parameters are described above in general terms (i.e., without specific reference to spin-lattice relaxation time T.sub.1 or spin-spin relaxation time T.sub.2), because it is known in the art that, in bulk fluids, T.sub.1 is roughly equivalent to T.sub.2, and any analysis based on differences in relaxation time behavior could involve either or both parameter(s).